Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Reservoir Description and Dynamics
Integration of 1D Geomechanics Modeling and High-Performance Water-Based Mud HPWBM System Design, Improving Cost-Effective Drilling of High-Angle Wells Through Cauvery Shale Sequence: A Case Study from Cauvery Basin, Offshore India
Saha, Sankhajit (Baker Hughes, a GE company) | Gariya, Bhuwan Chandra (Hindustan Oil Exploration Company Ltd) | Panda, Debabrata (Hindustan Oil Exploration Company Ltd) | Perumalla, Satya (Baker Hughes, a GE company) | Podder, Tuhin (Baker Hughes, a GE company) | Thanvi, Shrikant (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company)
Abstract Drilling through the thick shale sequence (Oligocene to Paleocene age) of Cauvery offshore showed severe wellbore instability in the past due to incompatible mud program that increased overall operational cost. While new high-angle sidetrack development wells had been planned, three major challenges need to be addressed. First, proper mud weight recommendation for preventing mechanical instability; second, introduction of a cost-effective mud system preventing time-sensitive failure; and finally, mitigating the environmental impact factor of the mud system. Geomechanical modelling and Hole Stability analysis had been performed based on available dataset. An optimized mud weight (MW) program was developed based on the analysis. Considering the time-dependent failure characteristics of the shale and overall cost effectiveness, just modifying the mud weight does not address all of the challenges delineated above. Consequently, special "high-performance water-based mud system (HPWBM)" was designed instead of oil-based mud (OBM). This HPWBM was formulated based on the nature of shales encountered. While drilling, real-time geomechanics further facilitated controlled drilling conditions and optimized the mud program. The well-based geomechanical model indicated a hydrostatic pore pressure gradient in the region. The relative magnitude of three principle stresses showed a normal fault stress regime and maximum horizontal stress (SHmax) azimuth appeared to be nearly aligned to the N-S direction. Hole Stability analysis showed that a minimum of 12 ppg mud weight was required to drill the 8½" section. The sidetrack holes had a maximum inclination of 75 to 77 degrees. Different polymers and bridging agents were added to prepare the customized HPWBM in order to address shale instability and formation damage due to overbalance. Real-time monitoring during drilling operation utilized logging while drilling (LWD) log data, drilling parameters and mud logging data to promote smooth drilling operations. Through systematic planning and execution, the high-angle sidetrack holes had been drilled with zero non-productive time (NPT) in terms of well bore stability. More than 50% cost reduction was achieved on the mud system. An integrated solution that includes pre-drill geomechanics, HPWBM system design and real-time well monitoring helped to reduce the risks due to model uncertainties while drilling high angle wells through the thick shale section. This approach helped to reduce significant operational cost with an improved success rate.
- Phanerozoic > Cenozoic > Paleogene (0.55)
- Phanerozoic > Mesozoic (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Asia > India > Tamil Nadu > Bay of Bengal > Cauvery Basin (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Zubair Formation (0.98)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Zubair Field > Mishrif Formation (0.98)
Development Optimization for Improving Oil Recovery of Cold Production in a Foamy Extra-Heavy Oil Reservoir
Yang, Zhaopeng (PetroChina Research Institute of Petroleum Exploration&Development) | Li, Xingmin (PetroChina Research Institute of Petroleum Exploration&Development) | Chen, Heping (PetroChina Research Institute of Petroleum Exploration&Development) | Ramachandran, Hariharan (The University of Texas at Austin, Hildebrand Department of Petroleum and Geosystems Engineering) | Shen, Yang (PetroChina Research Institute of Petroleum Exploration&Development) | Yang, Heng (China National Oil and Gas Exploration and Development Corporation) | Shen, Zhijun (China National Oil and Gas Exploration and Development Corporation) | Nong, Gong (China National Oil and Gas Exploration and Development Corporation)
Abstract The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area has been put into production about 10 years, existing problems of productivity declining and produced gas-oil ratio rising. Therefore, the development optimization for the early producing area should be conducted in order to obtain the more profitable oil recovery. A typical foamy oil reservoir simulation model using 5 components was created to understand the remaining oil distribution features. Based on above understandings, technical strategies were proposed for infilling well deployment in the early producing area. Results show that the gravity drainage and gravity differentiation of oil and gas during the cold production of foamy extra-heavy oil from horizontal wells by foam flooding are the main mechanisms for formation of remaining oil. And the influence factors of remaining oil distribution include horizontal well spacing, reservoir thickness, reservoir heterogeneity, interlayer distribution and reservoir rhythm. Thus tor foamy extra-heavy oil CHOP process, the enriched remaining oil area is the place between two adjacent horizontal wells with well spacing of 600m. Therefore, well infilling is an effective measure improving oil recovery factor of cold production, and the well infilling should be implemented as soon as possible to obtain better performance of cold production.
- Asia (0.47)
- North America (0.46)
- South America > Venezuela > Orinoco Oil Belt (0.34)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Cold heavy oil production (1.00)
Uncertainty Assessment of Burgan Marrat Carbonate Reservoir using Response Surface Modelling to Plan Early-Stage Field Development
Al-Shammari, Asrar (Kuwait Oil Company) | Gutierrez, Jeannire (IFP Middle East Consulting) | Sinha, Satyendra (Kuwait Oil Company) | Al-Shammari, Obaid (Kuwait Oil Company)
Abstract Burgan Marrat, a deep carbonate reservoir was transferred from exploration to development team for an accelerated production of the newly discovered oil. This multi-billion barrel reservoir is spread over 450 km, has more than 40 faults, 8 compartments with large variation in oil-water contact and reservoir/fluid characteristics. The objective of this work is to understand the key uncertainties and quantify their impact on the reservoir offtake rate and oil recovery by conducting uncertainty assessment. An interdisciplinary team identified the key uncertainty parameters expected to have significant impact on the reservoir development. The range and probability distribution law for each parameter was set considering the uncertainties due to limited measurements or variation in interpretations. A Response Surface Model (RSM) was created to evaluate the uncertainties by using a base dynamic model and applying an appropriate experimental design, which allowed to efficiently study the uncertainty space with a feasible number of simulations. Using the RSM, the primary effects and interaction between parameters were quantified to rank the uncertainties based on their impact on field production. Key uncertainty parameters were identified including eight OWCs, six fault transmissibilities, horizontal and vertical permeability multipliers, and porosity multiplier. Latin Hypercube was found to be the appropriate Experimental Design for the study considering 17 parameters and the need of building a reliable RSM that includes interactions between them. The design recommended 155 simulation cases, which were prepared and submitted automatically by the software. Multi-time Responses were analyzed qualitatively to identify the top 5 uncertainties having material impact on field production over 20 years considering 6 existing wells and 30 new well locations. The RSM quantitative evaluation showed three parameters (OWC2, OWC4 and OWC1) having a total effect on the response higher than 10%; followed by PERMX and OWC3 with less than 5%. The other 12 parameters have total effects less than 2%, and the interactions effect is less than 0.5% for any interaction between two parameters. Contrary to the intuition, none of the faults proved impact on the reservoir production. The results prove very useful to make a right development and appraisal strategy in early life of the reservoir. The new well locations can be ranked and prioritized to optimize the development and effectively appraise the areas with high risks. Uncertainty assessment has value throughout the life of the reservoir. However, this study indicates that its application in early life of the reservoir can bring immense value. An uncertainty analysis on the reservoir production helps in decision-making regarding the number of wells and their locations to reach a target production by managing the risks.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (3 more...)
Planning India's First CO2-EOR Project as Carbon Capture Utilization & Storage: A Step Towards Sustainable Growth
Mishra, Gaurav Kumar (Oil and Natural Gas Corporation Limited) | Meena, Rakesh Kumar (Oil and Natural Gas Corporation Limited) | Mitra, Sujit (Oil and Natural Gas Corporation Limited) | Saha, Kunal (Oil and Natural Gas Corporation Limited) | Dhakate, Vilas Pandurangji (Oil and Natural Gas Corporation Limited) | Prakash, Om (Oil and Natural Gas Corporation Limited) | Singh, Raman Kumar (Oil and Natural Gas Corporation Limited)
Abstract India is the fastest growing major economy and third largest CO2 emitter in the world. Keeping cognizance of country's energy requirement and commitment to climate change, embarking upon technologies having minimal carbon footprint is the need of the hour. Carbon capture, utilization and storage (CCUS) is one such technology which offers dual benefits of carbon sequestration & enhancing oil production from mature oils fields. This paper outlines ONGC's efforts in bringing nation's first CO2-EOR project. In view of non-availability of natural CO2 sources in India, usage of anthropogenic CO2 captured from thermal power plants was conceptualised. Based upon CO2 source-sink matching exercise and favourable reservoir & fluid parameters, two oil fields were screened. Technical feasibility of CO2-EOR was first ascertained in laboratory by determination of minimum miscibility pressure (MMP) of CO2 through slim tube experiments. Encouraged by laboratory results, full field compositional simulation studies along with fluid characterization inputs from PVT simulator were carried out. The MMP were found to be in range 190-250 Ksc, which is below the initial reservoir pressures of the targeted reservoirs. The proposed scheme entails drilling of around 70-80 wells inclusive of both producers & injectors and has the potential to yield an incremental recovery between 10-14 %. A sensitivity analysis based upon purity of CO2 and its adverse effect on MMP was carried out in terms of reduced oil recoveries. Since, this shall be a CCUS project, CO2 from the produced stream has to be separated, compressed and reinjected in a closed loop system. Around 5-8 MMT of CO2 will be sequestrated through Structural, Solubility and Residual trapping mechanisms as modelled in compositional simulator. IFT reduction & decrease in Sor (Residual oil saturation) as result of swelling, miscibility of CO2 with native oil were also modelled in simulator. Being first of its kind project in India, there are many inherent challenges to the CCUS project. At the source end, capturing CO2 from flue gas stream and its compression & transportation is a cost and energy intensive process. At the Sink end, CO2 being acidic and corrosive gas will need retrofit modifications in terms of special corrosion resistant metallurgy for existing processing facilities. The learning curve from this endeavour shall create knowledge base to further expand deployment of CCUS in India, bringing a large portfolio of reservoirs under the ambit of CO2-EOR. Success of CCUS in India will not only increase domestic oil production but also cater to address the National INDC of reducing emission intensity of GDP by 33-35 percent by 2030 as per Paris agreement.
- Geology > Rock Type (0.47)
- Geology > Petroleum Play Type (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > India Government (0.49)
- Asia > India > Rajasthan > Cambay Basin (0.99)
- Asia > India > Gujarat > Cambay Basin (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Modelling and Implementation of Dual Artificial Lift System for Production Enhancement: A Successful Case Study of Aishwariya Field
Khare, Sameer (Cairn Oil & Gas vertical of Vedanta Limited) | Baid, Rahul (Cairn Oil & Gas vertical of Vedanta Limited) | Prusty, Jyotsna (Cairn Oil & Gas vertical of Vedanta Limited) | Agrawal, Nitesh (Cairn Oil & Gas vertical of Vedanta Limited) | Gupta, Abhishek Kumar (Cairn Oil & Gas vertical of Vedanta Limited)
Abstract The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study. Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously. The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction. The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost. Novel Technique: No standard industry software can help model such dual lift systems with ease. The in-house developed workflow allows engineers to successfully model such complex lift scenario for routine production optimization and well surveillance activities.
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Aishwariya Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Aishwariya Field > Fatehgarh Formation (0.99)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Abstract Krishna Godavari Offshore Block has reservoir temperatures of 420 degF and 12,500 psi of bottom hole pressures, field's HPHT rating is a concern moreover other challenges like the wells are complex in terms of depths, profile, high drift, reservoir with heterogeneity, formation pressure variation. The paper discusses challenges during well planning and their execution with adequate methods to successfully drill and case well with less than 15 % NPT. In harsh environment of KG Basin, HPHT wells encroach on limits of equipment, leaving little margin for error, resulting in increased risk of rapid gas migration, equipment integrity failure, operating limits of tool. The paper discusses use of RSS-Vortex, 200 degC rated MWD tools, NRDPP, modified casing design, reduction in impact of side forces and high torques, optimized bit design, drill pipe cutting tool, reduction of differential sticking to execute the drilling of well within given time. The case study discusses longest 5 7/8" section drilled in an unconventional casing design under HPHT environment in India. The paper also discusses the unexpected results and observations obtained during execution of program and the lessons learnt from it. Some drilling methods such as first application of RSS-Vortex in a HPHT environment in India has considerably enhanced the ROP by 100% and also significantly reduced casing wear of production casing by 55 %, use of 200 deg C rated MWD tools has increased the robustness of the drilling BHA resulting in minimizing additional BHA trips due to tool failures. The reservoir section drilling has been optimized to 3 bit trips from 9-13 trips done in offset wells. Use of NRDPP's made drilling of high drifted wells easier and maintenance of surface torque within limits had considerably reduced lost production time and ensured safe operation. The improvisation carried out for bit design and casing design has also saved rig days and cost. The new casing design avoids liner tie back which has resulted saving of 7 days of rig time. The use of effective micronized barite OBM system with controlled measures on HTHP fluid loss has maintained good balance between rheology and fluid loss to prevent differential sticking. The downhole tool failure and stick-slip was reduced by 50% by modulating the Variable frequency drive and choosing adequate bit. These methods and practices require further optimization to enhance the usability. The established methods discussed have created good drilling practices in HPHT environment for KG field and has reduced the drilling NPT levels. Such a huge transformation in reducing the NPT is very significant in HPHT conditions and many of the practices can be standardized for such operations.
Abstract Digital core generated from micro CT images of rock sample cutting and results obtained from digital core analysis are presented in this work as a substitute of conventional core study for Petrophysical evaluation. Conventional core extraction during drilling, core preservation and analysis are expensive, time consuming processes and often unavailable for small size fields. Moreover, routine and special core analysis results are a critical input for petrophysical characterization. In this situation, digital core study appears to be a cost effective substitute to ensure and validate petrophysical evaluation results. High resolution 3D micro CT imaging and analysis was done on rock samples cut during drilling or on sidewall core plugs cut by wireline logging tool. Segmented micro CT image slices when combined in 3D space in three orthogonal directions, can be termed as digital core. Solid rock matrix, clay filled and porous rock portions are distinctly separable using micro CT images and their volume fractions can be estimated. Detail textural analysis in terms of Grain and pore throat size distribution of the rock is possible from digital core which controls storage capacity and flow behavior. Two critical petrophysical input parameters for fluid saturation (Sw) estimation are cementation exponent (m) and saturation exponent (n). These parameters are commonly computed from special core analysis (SCAL) on conventional core plugs. But digital core study can provide the estimates of ‘m’ and ‘n’ which replace the need of SCAL. Digital core study has been carried out in three different reservoirs in west and east coast of India and the results were analyzed. Porosity and permeability data obtained from digital core was first compared with log analysis results and then used to identify different petro physical rock types (PRT). Fluid saturation (Sw) was estimated from resistivity log by using ‘m’ and ‘n’ exponent obtained from digital core seems to be more realistic and corroborates with well test results. Porosity, permeability, water saturation and rock types (PRT) were helped to build geo-cellular model (GCM) for small and marginal reservoir. Enhanced reservoir characterization by using digital core study result has helped in better understanding and decision making for small and marginal fields where limited well data is available. Finally this leads to the preparation of field development plan (FDP). Digital core technique is less expensive, having quick turnaround time than conventional coring which has translated into high value business impact for any development project.
- Asia > India (1.00)
- Asia > Middle East > Saudi Arabia (0.16)
- North America > United States > Texas (0.15)
- Geology > Geological Subdiscipline (0.96)
- Geology > Mineral > Silicate (0.50)
- Asia > India > Tamil Nadu > Bay of Bengal > Cauvery Basin (0.99)
- Asia > India > Rajasthan > Cambay Basin (0.99)
- Asia > India > Gujarat > Cambay Basin (0.99)
- Asia > India > Andhra Pradesh > Bay of Bengal > Krishna-Godavari Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Efficient Horizontal Wellbore Placement and Completion with Geosteering and Zonal Isolation in a Reservoir on Waterflood: A Case Study of Western Offshore, India
Kisku, Sayanima (Oil & Natural Gas Corporation Ltd.) | Santhosh Kumar, R.. (Oil & Natural Gas Corporation Ltd.) | Dayal, Har sharad (Oil & Natural Gas Corporation Ltd.) | Chadha, Harish Kumar (Oil & Natural Gas Corporation Ltd.) | Srivastava, Anil (Oil & Natural Gas Corporation Ltd.)
Abstract Infill drilling is an integral part of brown field management for exploiting un-drained areas with good oil saturation. In a matured field on water-flood, the primary objective is optimized wellbore placement of infill wells in areas with better petro-physical characteristics, bypassing flooded region. It is also important to design a robust completion strategy to safeguard the longevity of these wells by curtailing produced water. This approach assists in dramatic increase in production by isolating water charged sections and thereby restricting rise in water production. The use of advanced Logging-While-Drilling techniques during horizontal drilling provides an opportunity for effective well planning. Real-time Logging-While-Drilling instruments during directional drilling gives us the opportunity to acquire information pertaining to the reservoir in a single run. Interpretation from the real-time data acquisition boosts the planning during wellbore drilling. This paper discusses a case study of a field in western offshore, India, which focuses on the applications of geosteering and the use of swell packers for zonal isolation to augment oil production. In this study, two wells have been deliberated where the real-time information has been extracted and included in the decision making process. The bottom-hole assembly used in this case, comprised standard Logging-While-Drilling services such as gamma ray, resistivity, neutron porosity, density and density imaging services and also formation pressure testing. Since the field under study is a carbonate reservoir that has been on waterflood for the last twenty eight years, chances of early breakthrough of water in the infill wells has posed a high risk in spite of the presence of good bypassed oil saturation. Geosteering has enabled to restrict the horizontal section safely within the desired zone of better oil saturation and geological features, as interpreted from the Logging-While-Drilling data. Further isolation of suspected water bearing zones with swell packers have assisted in healthy well completion by diminishing chances of sharp rise in water cut in the infill wells.
- North America > United States > Texas (0.88)
- Asia > India (0.86)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
Abstract Immiscible water-alternating-gas (iWAG) flooding is often considered as a tertiary recovery technique in waterflooded or about-to-be waterflooded reservoirs to increase oil recovery due to better mobility control and potentially favorable hysteretic changes to phase relative permeabilities. In such cases, typically, reservoir simulation models already exist and have been calibrated, often modifying saturation functions during the history matching stage. However, to utilize such models in forecasting iWAG performance, additional parameters may be required. These can be acquired by simulation of WAG coreflood experiments. While in many published cases, the parameter values obtained from matching experimental results are used without modification, this may not be advisable since the parameters are only valid at the core scale at which they were obtained. This paper discusses the challenge of systematically upscaling WAG parameters obtained at core scale to an existing full field model. In this work, we use a multi-stage upscaling process from core scale to full field scale. The first stage uses a core scale model to match ‘representative’ core flood experiments and obtain WAG parameters. The second uses a well-to-well high-resolution 1D section of the full field model populated using gridblocks of core size to generate ‘reference’ WAG performance using the unaltered WAG parameters obtained from core. The third stage uses a similar 1D model but populated using gridblocks at full field model resolution to match the results from the reference model while adjusting the WAG parameters as little as possible. Finally, a model using the full field model resolution as well as the full field relative permeability functions which, it is assumed, have been tuned to match the history and account for dispersion is used to match the reference model results and obtain final upscaled WAG parameters. The upscaled WAG parameters obtained at the end of this multi-stage process can be used at the field scale. This process allows clear quantification of the uncertainty associated with the upscaling process. Simulations at the third stage showed that once the full field to core scale grid size ratio exceeded a certain point (2500:1), there was a marked increase in the difference between upscaled and reference model results. It was found that if WAG parameters were changed in the full field model resolution model in order to match recovery results in the reference model, Land's parameter could change by up to 10% and relative permeability reduction factor could increase by up to 30% although it is expected that this will vary from case to case. It is therefore recommended to identify and use full field model resolutions to as close to the threshold as possible. The practice of using the core scale iWAG parameters in the full field model directly could under-estimate actual recovery, and overestimate injectivity. When considering the WAG mechanism alone, the value of the recovery underestimate increasing with pore volumes injected and, in our case, by up to 7% after injecting 1 pore volume of fluid. This multi-stage simulation approach helps identify the adjustments required and uncertainties associated with simulating iWAG flooding in reservoir models. This approach utilizes options widely present in commercially available finite difference simulators, addresses the challenge of utilizing existing pseudo functions and provides a practical methodology through which iWAG performance forecasting can be improved.
- Asia (1.00)
- North America > United States > Texas (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
Abstract Panna Formation is a very critical and challenging formation deposited during Paleocene time of geological past in various parts of Western Offshore Basin of India. It was deposited in a fluvio-deltaic environment, sometimes even in a restricted marine set-up. Such variation in depositional setting caused mineralogical complexity, which in-turn imposed a limitation in conventional approach of formation evaluation and saturation determination to identify the pay zones with confidence. A comprehensive approach of integrated formation evaluation for rock quality characterization was attempted using a combination of new generation elemental and acoustic analysis for delineating the potential hydrocarbon bearing zones independent of conventional resistivity-based approach along with a better insight on formation heterogeneity. The studied well was drilled up to Panna Formation and conventional open-hole logs were acquired while drilling. However, due to complex mineralogical nature of the formation, estimation of key critical reservoir parameters was very challenging and imposed higher uncertainties in the results. An alternate approach was adopted using a few advanced log measurements to address this challenge. A combination of new generation elemental and acoustic data has been recorded in a single wireline run after acquiring conventional basic logs while drilling. An accurate porosity was derived by eliminating various mineralogical assemblages along with estimation of a geochemical permeability based on detailed elemental analysis. Measured aluminum from neutron inelastic capture spectrum method enabled to estimate clay volumes with accuracy, which provided the required insight for better effective porosity in such shaly-sand environment. Based on this improved porosity and permeability, an approach for rock-quality indexing was used for reservoir delineation. Moreover, a good amount of organic carbon was found associated with clays caused shales with higher resistivity. Based on elemental measurements an interesting insight was possible to extract for resistivity independent fluid saturation. An additional pay zone with hydrocarbon saturation based on such resistivity independent approach was possible to identify, which was masked by conventional resistivity-based interpretation. Acoustic analysis results assisted in delineating the zones with possible open fractures to avoid any possibility for unwanted fluid breakthrough. Based on this approach of alternate integrated petrophysical analysis perforation zones were selected including an additional zone, which was masked based on conventional analysis. The well was started producing around 1,05,000 m3 gas with around 200 barrels of oil per day. This study showcased an alternate and efficient characterization approach for any such mineralogically challenging clastic formations.
- North America > United States (1.00)
- Asia > India > Maharashtra > Arabian Sea (0.28)
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.87)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Deltaic Environment (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.34)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-V Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-IV Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-III Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)